In the process of rotary drilling a well, a drilling fluid or mud is circulated down the rotating drill pipe, through the bit, and up the annular space between the pipe and the formation or steel casing, to the surface. The drilling fluid performs different functions such as removal of cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when the circulation is interrupted, control subsurface pressure, isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, cool and lubricate the drill string and bit, maximise penetration rate etc. An important objective in drilling a well is also to secure the maximum amount of information about the type of formations being penetrated and the type of fluids or gases in the formation. This information is obtained by analysing the cuttings, by electrical logging technology and by the use of various downhole logging techniques, including electrical measurements.
The required functions can be achieved by a wide range of fluids composed of various combinations of solids, liquids and gases and classified according to the constitution of the continuous phase mainly in two groupings: aqueous drilling fluids, and non-aqueous drilling fluids.
Aqueous fluids are the most commonly used drilling fluid type. The aqueous phase is made up of fresh water or, more often, of a brine. As discontinuous phase, they may contain gases, water-immiscible fluids such as diesel oil which form an oil-in-water emulsion, and solids including clays and weighting material such as barite. The properties are typically controlled by the addition of clay minerals, polymers and surfactants.
In drilling water-sensitive zones such as reactive shales, production formations, or where bottom hole temperature conditions are severe or where corrosion is a major problem, non-aqueous drilling fluids are preferred. The continuous phase is typically a mineral or synthetic oil and commonly contains water or brine as discontinuous phase to form a water-in-oil or invert emulsion. Non-aqueous fluids also typically contain a solid phase, which is essentially similar to that of aqueous fluids, and additives for the control of density, rheology and fluid loss. The invert emulsion is formed and stabilised with the aid of one or more specially selected emulsifiers.
Although non-aqueous drilling fluids are more expensive than water-based muds, it is because of their superior technical performance that they are often used for drilling operations.
However, because of their very low electrical conductivity oil-based muds have been at a technical disadvantage in the area of electrical well-logging. Various logging operations are performed during the drilling operation, for example while drilling in the reservoir region of an oil/gas well, in order to image or otherwise analyse the type of formation and the material therein. In this way it is possible to locate the pay zone, i.e. where the reservoir is perforated in order to allow the inflow of hydrocarbons to the wellbore.
Some logging tools work on the basis of resistivity contrast at different parts of the formation. These are known as resistivity logging tools. Briefly alternating current flows through the formation between electrodes of the logging tool. The fluid in the formation comprises intrinsic formation fluid and filtrate which has penetrated the formation from the wellbore. Thus the resistivity of the formation will vary depending on e.g. the permeability of the formation and the ratio of formation fluid to filtrate in the formation.
At present the use of resistivity logging tools is limited mainly to cases where an aqueous drilling fluid is used for the drilling operation, as the very low conductivity of the non-aqueous continuous phase in e.g. oil-based muds precludes the use of resistivity tools in such fluids. Although brine dispersed in the non-aqueous continuous phase is electrically conductive, the discontinuous nature of the droplets prevents the flow of electricity. Indeed, the inability of such emulsions to conduct electricity (until a very high potential difference is applied) is used as a standard test of emulsion stability. The electrical conductivity of the oil-base of a typical non-aqueous wellbore fluid is commonly in the range 10−8 to 5×10−4 ìS·cm−1 at 20° C. while an electrical conductivity of not less than 0.1 ìS·cm−1 and preferably of not less than 10 ìS·cm−1 is desirable for electrical logging operations.
Another example where fluid conductivity plays an important part in the drilling operation is in directional drilling where signals produced at the drill assembly are transmitted through an electrically conductive medium to the control unit and/or mud telemetry unit further back on the drill string.
In our previous application WO 99/14285 we described wellbore fluids with a non-aqueous continuous phase comprising a polar organic liquid and a dissolved quaternary ammonium salt (e.g. tetrabutyl ammonium halide) which forms an organic cation in solution. While it is possible in this way to increase significantly the conductivity of the wellbore fluid, a problem remains that such salts can be toxic e.g. to marine animal life. Therefore, such fluids may not be suitable for use in off-shore hydrocarbon recovery operations.
Salts which produce organic anions have also been investigated with the aim of imparting conductivity to non-aqueous solubilising agents. Thus, for example, magnesium oleate as been used as an anti-static additive in dry-cleaning fluids (see e.g. W. F. Whitmore and M. Lauro, Ind. Eng. Chem., 22, 646-649, (1930) and H. Silman, Soaps, 12, 31-33, (1936))). However, such investigations have not generally been pursued in the area of hydrocarbon recovery because commonly-available, organic anion-producing salts, such as metal oleates, have low solubilities in the continuous phase of typical non-aqueous wellbore fluids.
An object of the present invention is to provide an electrically conductive non-aqueous wellbore fluid with a low toxicity.
Definitions
The term “organic”, when used herein, pertains to compounds and/or groups which comprise, at least, carbon atoms.
The terms “carbo”, “carbyl”, “hydrocarbo” and “hydrocarbyl”, when used herein, pertain to compounds and/or groups which have only carbon and hydrogen atoms.
The term “ring”, when used herein, pertains to a closed ring of from 3 to 10 covalently linked atoms, more preferably 3 to 8 covalently linked atoms.
The term “cyclic”, when used herein, pertains to compounds and/or groups which have one ring, or two or more rings (e.g. spiro, fused, bridged). Compounds with one ring may be referred to as “monocyclic” or “mononuclear” whereas compounds with two or more rings may be referred to as “polycyclic” or “polynuclear”.
The term “aliphatic”, when used herein, pertains to compounds and/or groups which are linear or branched, but not cyclic (also known as “acyclic” or “open-chain” groups).
The term “aromatic ring”, when used herein, pertains to a closed ring of from 3 to 10 covalently linked atoms, more preferably 5 to 8 covalently linked atoms, which ring is aromatic.
The term “heterocyclic ring”, when used herein, pertains to a closed ring of from 3 to 10 covalently linked atoms, more preferably 3 to 8 covalently linked atoms, wherein at least one of the ring atoms is a multivalent ring heteroatom, for example, nitrogen, phosphorus, silicon, oxygen, and sulphur, though more commonly nitrogen, oxygen, and sulphur.
The term “aromatic”, when used herein, pertains to compounds and/or groups which have one ring, or two or more rings (e.g., fused), wherein said ring(s) are aromatic.
The term “alicyclic”, when used herein, pertains to compounds and/or groups which have one ring, or two or more rings (e.g., spiro, fused, bridged), wherein said ring(s) are not aromatic.
The term “straight chain”, when used herein, pertains to a chain of consecutively linked atoms, all of which or the majority of which are carbon atoms. Side chains may branch from the straight chain, but the number of atoms in the straight chain does not include the number of atoms in any such side chains.
By “non-aqueous wellbore fluid” we mean a fluid (such as a drilling fluid, fracturing fluid etc.) which has a non-aqueous continuous phase formed from oil, synthetic base, natural base, or a mixture thereof. Examples of typical oils are crude oil, and hydrocarbon refined fractions from crude oil such as diesel fuel or mineral oil. Examples of typical synthetic bases are synthetic hydrocarbons such as n-paraffins, alpha-olefins, internal olefins and poly-alphaolefins; and synthetic liquids such as dialkyl ethers, alkyl alkanoate esters and acetals. Examples of natural bases are triglycerides such as rape-seed oil and sunflower oil. Discontinuous phases, such as aqueous emulsions (e.g. formed from brine) and solids (e.g. clays and barite or hematite weighting agents), may be present in the fluid. Furthermore, the fluid may contain additives such as polymers and surfactants e.g. to stabilise emulsions or to act as fluid loss control agents.
By an “oligomeric” or “oligomer” organic salt we mean that the structure of the salt is based on from two to eight (preferably two to five, and more preferably two or three) linked organic salt subunits, each subunit having a negatively charged head group and an organic tail group which is bonded at a terminal atom thereof to the head group. The subunits are linked head group-to-head group in the oligomer, by (e.g. C1, C2, C3, C4, C5, or C6) organic (preferably aliphatic and/or hydocarbyl) linkage groups or covalent bonds. The oligomer, therefore, has distinct tail groups corresponding to the tail groups of the subunits and a super-head group formed from the plural head groups of the subunits. Although the oligomer is defined in relation to a chemically-corresponding subunit, in practice the oligomer surfactant may be synthesised using a different subunit. For example, a synthesis route may be adopted in which subunits are first oligomerised and the head groups are then changed to those of the desired negatively charged head group. That is, the head groups of the subunits used for the oligomerisation may be different from the head groups of the subunits to which the final oligomer chemically corresponds.